1. Technical Field of the Invention
The present invention generally relates to Claus sulfur recovery plants and to processes for recovering sulfur from H2S-containing gas streams. More particularly, the invention relates to a Claus process and apparatus in which the combustion stage is replaced by a catalytic partial oxidation stage in which elemental sulfur and sulfur dioxide is produced.
2. Description of the Related Art
Sulfur-recovery plants, also called Claus plants, are well known for removing hydrogen sulfide gas (H2S) resulting from petroleum refining processes and other industrial processes by converting the H2S to elemental sulfur. A conventional modified Claus process includes two primary stages: a thermal or combustion stage and a catalytic or “Claus” stage. In the thermal stage, which is carried out in a furnace, the H2S gas is contacted with a stoichiometric amount of air or a mixture of oxygen and air in a flame so that about one third (⅓) of the H2S is combusted according to the reaction:H2S+3/2O2→SO2+H2O  (1)Reaction 1 is highly exothermic and not limited by equilibrium. Still in the reaction furnace, a portion of the uncombusted H2S (i.e., about ⅔ of the initial amount in the feed) reacts with some of the sulfur dioxide (SO2) product to form elemental sulfur (S0) and water vapor according to the reaction:H2S+½SO2⇄3/xS0x+2H2O  (2)(x=2, 6, or 8 depending on the temperature and pressure.) Chemical Reaction 2, which is sometimes referred to as the “Claus reaction,” is endothermic, and the extent of conversion of the H2S and SO2 to elemental sulfur is limited by the chemical equilibrium of the reaction. In the thermal stage a total of about 55 to 70% of the H2S in the original feed is converted to elemental sulfur. To improve the yield, the reacted gases are cooled in a fire tube boiler after emerging from the reaction furnace and elemental sulfur is condensed from the gas stream and removed in molten form, whereupon the gases enter a catalytic stage, which is carried out in a series of catalytic reactors.
In the catalytic stage, the gases are reheated and then passed over a catalyst bed that promotes the Claus reaction and further converts the process stream to elemental sulfur according to the Claus reaction. Because of the reversible chemical equilibrium of the Claus reaction (Reaction 2), the formed products can react according to the reverse Claus reaction3/xS0x+2H2O⇄H2S+½SO2  (3)with the effect of reducing the efficiency of the Claus plant. The reverse Claus reaction becomes more pronounced as reactor temperature increases. By removing formed elemental sulfur from the process gas exiting the thermal stage, the forward Claus reaction is made more favorable. Following the thermal stage, in the catalytic stage the sulfur depleted gases are reheated, catalytically reacted, and again cooled to condense and separate an additional increment of sulfur. In the catalytic stage, the remaining H2S is reacted with the SO2 (at lower temperatures, i.e., about 200-350° C.) over a catalyst to make more sulfur. The catalyst promotes the Claus reaction (Reaction 2), however even the best catalysts cannot cause the Claus reaction to go to completion. For this reason, additional catalytic reactors are necessary to remove sequential increments of sulfur. Factors like concentration, flow rate and reaction temperature influence the reaction. From one to four sequential stages of reheating, catalytic reacting and condensing are usually employed industrially. In a typical modified Claus plant in which two or three catalytic reactors are employed, about 90 to 98% of the H2S originally fed to the plant is recovered as elemental sulfur. Any remaining H2S, SO2, sulfur, or other sulfur compounds in the Claus plant effluent are usually either incinerated to SO2 and discharged to the atmosphere, or incinerated to SO2 and absorbed by chemical reaction, or converted by hydrogen to H2S and recycled or absorbed using any of a variety of well known Claus tail gas treatment units which improve the efficiency of sulfur removal from the gas discharged to the atmosphere. One example is the well-known SCOT™ process for cleaning up the tail gas from the process. Other common treatments involve absorption of sulfur-containing compounds in the tail gas by an alkanolamine solution.
A conventional modified Claus process can be used efficiently for processing large quantities of gases containing a high concentration (i.e., >40 vol. %) H2S in Claus plants producing more than 7,000 tons of sulfur per year. The modified Claus plants in use today are normally operated at less than 2 atmospheres pressure. Because of this low pressure, the pipes and vessels have very large diameters for the flow compared to most refinery or gas plant processes. The low pressure operation forces the equipment to be designed for low pressure drop to have adequate capacity. Therefore, a typical modified Claus plant, together with one or more tail gas treatment units, is large and the plant includes a great deal of equipment. Over the years, various changes to the modified Claus process and apparatus have been suggested, many of which are directed primarily toward improving or replacing the thermal reactor.
For example, U.S. Pat. No. 4,279,882 (Beavon) discusses eliminating the thermal reactor, including the combustion chamber and heat exchanger, and instead producing sulfur by contacting with a catalyst a feed gas comprising an acid gas stream containing from about 1-100% (by volume) H2S in admixture with about 70-130% of the stoichiometric amount of oxygen required for conversion of hydrogen sulfide to sulfur, and a recycle gas, to form a gas stream comprising hydrogen sulfide, sulfur dioxide and sulfur at a temperature between the kindling temperature of the catalyst and about 850° F. The catalyst is selectively capable of oxidizing hydrogen sulfide to sulfur dioxide substantially without formation of sulfur trioxide. The recycle gas is a portion of the gas resulting from condensing sulfur from the effluent of the catalytic selective oxidation zone. Catalysts such as vanadium oxide and vanadium sulfide on a non-alkaline porous support are described.
Even though modified Claus processes are efficient and proven processes for many applications in commercial use today, that technology has certain inherent limitations that erode its usefulness in many industrial situations. Some of the major drawbacks of existing Claus technology arise from a) the inability to process H2S streams containing less than about 20% H2S, b) hydrocarbon contamination of the feed gas, c) excessive carbon dioxide (CO2) in the feed gas, d) ammonia in the feed gas, e) insufficient residence time in the burner/reaction chamber, and f) excessive pressure drop caused by flow friction.
Insufficient H2S concentration in the feed. One problem with conventional Claus plants used in industry today is the inability to efficiently handle feed gas streams in which the H2S content is 20% or less. Although Reaction 1 is highly exothermic, if there is too little H2S in the feed stream, the heat of reaction will be insufficient to perpetuate the reaction without the addition of heat from another source. Typically the Claus feed must contain more than about 20% H2S (by volume) in order to support a flame in the Claus burner. Thus, sour gas streams containing less than about 20% H2S cannot be satisfactorily desulfurized in a conventional Claus or modified Claus process. The difficulty of maintaining a workable flame temperature in the Claus burner is also discussed in U.S. Pat. No. 4,279,882 (Beavon). In practice, the flame temperature is often sustained by adding hydrocarbon gas as a fuel. This, however, significantly complicates control of the process, creates the danger of forming tarry products and discolored sulfur, and reduces the recovery of sulfur by forming water, a reaction product which is adverse to the Claus equilibrium. It also amplifies the problem of forming carbonyl sulfide and carbon disulfide, which are difficult to convert on a continuous basis in the Claus plant.
Hydrocarbon contamination of the feed. The presence of hydrocarbons in the H2S feed to a Claus plant may also result from releasing dissolved light alkanes from alkanolamine or other gas treating solutions into the Claus feed gas stream. This can occur as a result of a conventional solvent regeneration process, releasing methanol or aromatic hydrocarbons such as benzene along with H2S. Hydrocarbons in the Claus feed can burn before the H2S reaction to SO2 takes place, thereby starving the reaction (Reaction 1) of air and reducing its efficiency. The same volume of methane as H2S in the feed requires four times as much air for complete combustion as does the oxidation of H2S to sulfur, and the combustion of methane also releases more heat in the process. This can temporarily deprive the H2S oxidation reaction of the necessary oxygen, and thus reduces the production of SO2 and ultimately reduces the sulfur recovery efficiency of the unit. Another drawback of the presence of hydrocarbons in the Claus feed is that the hydrocarbons can form soot, a mixture of unburned hydrocarbon and solid carbon, when the hydrocarbon is burned in a reducing environment. Soot can deposit on the catalyst in the latter stages of the Claus process, causing loss of catalyst activity and catalyst bed plugging.
Hydrocarbons in the Claus feed can also react with H2S to form COS and CS2. Not only does this further reduce sulfur recovery efficiency, if those compounds emerge unconverted from the Claus plant, they are likely to end up as sulfur dioxide emissions after incineration of the Claus plant tail gas. This can be very important in many locations throughout the world where sulfur dioxide emissions are closely regulated. Completely combusting the hydrocarbon feed components in the Claus reaction furnace will also produce a large volume of combustion gases, in addition to consuming a greater amount of air to support the combustion than would otherwise be required to support the combustion of the H2S component. The combination of more hydrocarbon combustion products, with the added nitrogen from air, when air is used as the source of oxygen, leads to the further problem of excessive flow friction.
Excessive carbon dioxide in the feed. In many gas treating applications, H2S is usually removed by solvents, with subsequent regeneration and recycle of the solvent. Usual solvents include aqueous solutions of alkanol amines, such as monoethanolamine (MEA), diethanolamine (DEA), diisopropylamine (DIPA), and methyldiethanolamine (MDEA). The H2S-containing gaseous stream is contacted with the amine solution at relatively low temperatures in an absorber to remove the H2S. This step produces a rich amine stream, loaded with H2S. This rich amine is then passed to a stripper/regenerator, usually a tray type column where the solvent is heated to release the H2S, leaving a lean amine stream that can be recycled as fresh solvent to the absorber. Oftentimes CO2 is present in significant amounts along with the H2S. In natural gas, for example, typically the CO2 is absorbed by the solvent concurrently with the H2S. Because the CO2 is released along with the H2S in the treating solvent regeneration step, it becomes part of the Claus plant feed along with H2S. As the concentration of carbon dioxide increases in the feed, the heat release per unit volume of feed gas drops, which may make an H2S flame impossible, thus rendering the burner of the Claus plant inoperative. As described in U.S. Pat. No. 6,506,349 (Khanmamedov), one way to address this problem is to use a solvent that is selective for H2S in the presence of CO2. Another way that some processors have compensated for the CO2-related heat drop is by supplementing the feed with hydrocarbon in order to increase the flame temperature by combustion of hydrocarbon. As discussed above, this solution to the carbon dioxide problem then exacerbates the problems associated with hydrocarbon contamination of the Claus feed.
Ammonia in the feed. The presence of ammonia in Claus plant feed gases is common in the oil refining industry. For instance, ammonia results from denitrification of oils simultaneously with desulfurization that forms H2S. When ammonia is present in the Claus feed, it reacts in the flame/reaction furnace in a step-wise manner according to the reaction:H2S+3/2O2→SO2+H2O  (4)followed by the reaction:6SO2+8NH3→3S2+4N2+12H2O  (5)This requires oxygen from air to combust the H2S first, then adequate time for the ammonia and SO2 to react, usually about 1 second for a typical Claus reaction furnace. The size of the reaction tube and the temperature inside the reaction tube are important factors in determining whether the ammonia conversion is taken to completion (Reaction 5). Ammonia that is not converted in the thermal stage can deposit in the back end of the plant in the form of ammonium sulfate or as various sulfate salts, or can pass through to the incinerator and be emitted as ammonia salts which can create an undesirable visible plume from the incinerator stack. U.S. Pat. No. 3,987,154 (Lagas) describes one process for removal of hydrogen sulfide and ammonia from a gaseous stream which endeavors to avoid clogging of the system as a result of ammonia combining with acidic compounds like H2S, SO2, SO3 and nitrogen oxides forming salts that may deposit as solids.
Insufficient residence time in the reaction furnace. In a typical modified Claus plant, the reacted gas mixture leaving the reaction furnace goes immediately to a waste heat exchanger to cool the reaction gases to prepare the mixture for sulfur condensation. Over their operational lifetimes, Claus plants have had to operate at ever increasing capacity in order to accommodate increased loads. Thus, the amount of time each portion of reaction mixture leaving the burner spends at high temperature in the reaction furnace has decreased as a result. By shifting the reacted gases to lower temperatures more quickly, the Claus equilibrium conversion curve (of Reaction 2) is pushed toward lower levels of conversion. Because of the increased load on the catalyst beds, this can also lead to higher emissions of unconverted compounds such a COS and CS2. Insufficient gas residence time may also prevent complete ammonia conversion to nitrogen and water products (Reaction 5) and lead to unit plugging or incinerator plumes.
Excessive pressure drop. The primary factor that determines the capacity limits of a Claus unit is the pressure drop that is available to accommodate the flow through the plant and the pressure drop needed to operate the instruments and control valves. As capacity demand increases, the pressure drop due to control losses and friction due to flow increase eventually allows for no more flow through the unit.
Another notable problem with conventional Claus plants is that not only are tail gas treatment units quickly overwhelmed when employed in a high capacity Claus plant with greater than few % H2S concentration in the tail gas, but the added expense of tail gas treatment is prohibitive for commercial industrial applications. U.S. Pat. No. 5,700,440; U.S. Pat. No. 5,807,410 and U.S. Pat. No. 5,897,850 describe some of the limitations of existing tail gas treatment (TGT) processes and the difficulty of meeting increasingly stringent government requirements for desulfurization efficiency in the industry. In what are generally considered the most efficient Claus tail gas treatment processes for removing H2S, a catalyst that is capable of promoting the direct oxidation of H2S according to the reactionH2S+½O2→½S2+H2O  (6)to produce elemental sulfur and water is employed at low temperature (i.e., above the dewpoint of sulfur but below about 350° C., typically less than 245° C.). As explained in U.S. Patent Application Publication No. 2001/0008619 (Geus et al.), a drawback of many direct oxidation catalysts used for selective oxidation of sulfur compounds is that upon substantially complete conversion of H2S to elemental sulfur, the oxidation of the produced sulfur to SO2 increases with increasing temperature. Conventional direct oxidation catalysts operate at temperatures below 500° C., typically staying between the dewpoint of sulfur and 350° C. Because Reaction 6 is not a thermodynamically reversible reaction, direct oxidation techniques offer potentially higher levels of conversion than is typically obtainable with the thermal and catalytic stages of a modified Claus process.
Most direct oxidation methods are only applicable to sour gas streams containing relatively small amounts of H2S and large amounts of hydrocarbons. For instance, U.S. Pat. No. 4,311,683 (Hass et al.) describes a process for removal of hydrogen sulfide from gas streams employing a catalyst that is selective for the oxidation of H2S at low temperatures (121-232° C.). In that process, such highly oxidizable components as H2, CO and light hydrocarbons, which all might be present in the H2S stream, remain essentially completely unoxidized. Such processes are generally not particularly well suited for handling the more concentrated acid gas streams from refineries, however. For this reason direct oxidation methods have been generally limited to use as tail gas treatments only, and have not found general industrial applicability for first stage sulfur removal systems from gases containing large quantities of H2S. The restriction to low H2S concentration gases is due, in part, to the increase in adiabatic heating of the catalyst bed that occurs at higher concentrations of H2S, i.e., above about 3 vol % H2S in the feed. The limit of heat tolerance of the reaction vessel, which is typically made of steel, can be quickly reached and exceeded when a high concentration of H2S is reacted. Also, increased temperature (i.e., above about 350° C.) typically causes an unacceptable increase in the rate of reaction of SO2 formation. The H2S concentration range is usually kept low because of the necessity for supplying excess O2 to overcome deactivation of most direct oxidation catalysts caused by water. As a practical matter, this need for a stoichiometric excess of O2 precludes using H2S concentrations above about 2 vol. %.
U.S. Pat. No. 5,597,546 (Li et al.) describes a method of selectively oxidizing hydrogen sulfide to elemental sulfur, in which a H2S-containing gas mixture contacts with an oxygen-containing gas at 50-500° C. in the presence of a bismuth-based catalyst. The reaction product mixture contains substantially no sulfur dioxide. The bismuth-based catalyst may further contain molybdenum or vanadium atom. R. H. Hass et al. (Hydrocarbon Processing May 1981:104-107) describe the BSR/Selectox™ process for conversion of residual sulfur in Claus tail gas or for pre-Claus treatment of a gas stream. K-T Li et al. (Ind. Eng. Chem. Res. 36:1480-1484 (1997)) describe the SuperClaus™ TGT system, which uses vanadium antimonate catalysts to catalyze the selective oxidation of hydrogen sulfide to elemental sulfur. U.S. Pat. No. 6,521,020 (Butwell et al.) and U.S. Pat. No. 5,603,913 (Alkhazov et al.) describe several oxide catalysts that are said to be capable of catalyzing the direct oxidation of H2S to elemental sulfur. U.S. Pat. No. 6,506,356 (Chung et al.) discusses the problem of deactivation of many tail gas treatment catalysts by the presence of water. Certain vanadium-titanium based mixed metal oxide catalysts are described which are said to be capable of selectively oxidizing H2S to elemental sulfur at low temperatures in the presence of excess moisture. A method employing such catalysts for recovering elemental sulfur from a reaction gas containing 0.5-40 vol % H2S and 30-50 vol % moisture is described.
Despite the advancements that have been made in direct oxidation processes for treatment of Claus tail gases, none of the existing methods are capable of providing sufficiently high levels of H2S conversion and selectivity for production of sulfur in a single-pass reaction from concentrated H2S streams. No existing direct oxidation process has been used to effectively take the place of the thermal stage of a conventional modified Claus process. Existing H2S direct oxidation processes do not adequately address the typical reactor temperature limitations nor do they operate at sufficiently high flow rates to be sufficiently useful industrially other than as tail gas treatments. Neither are they able to adequately address other major problems with today's modified Claus processes and plants, including a) hydrocarbon contamination of the feed gas, b) excessive CO2 in the feed gas, c) ammonia in the feed gas, d) insufficient residence time in the burner/reaction chamber, e) excessive pressure drop caused by flow fiction; and f) inability to process H2S streams containing less than about 20% H2S. Better systems and processes for removing sulfur from H2S and avoiding the problems discussed above would find widespread applicability in a number of industrial situations.